Review on Surfactant Flooding Phase Behavior, Retention IFT and Field Applications

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Review
Review on Surfactant Flooding: Phase
Behavior, Retention, IFT and Field Applications
Muhammad Shahzad Kamal, Ibnelwaleed A. Hussein, and Abdullah S Sultan
Energy Fuels , Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00353 • Publication Date (Web): 06 Jul 2017
Downloaded from http://pubs.acs.org on July 6, 2017
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1

Review on Surfactant Flooding: Phase Behavior, Rete ntion,
IFT and Field Applications
Muhammad Shahzad Kamal 1, Ibnelwaleed A. Hussein 2 *, Abdullah S. Sultan 3
1
Center for Integrative Petroleum Research, King Fah d University of Petroleum &
Minerals, 31261 Dhahran, Saudi Arabia

2 Gas Processing Center, College of Engineering, Qata r University, PO Box 2713, Doha,
Qatar
3 Department of Petroleum Engineering, King Fahd Univ ersity of Petroleum & Minerals,
31261 Dhahran, Saudi Arabia

*Corresponding Author: Ibnelwaleed A. Hussein,
ihussein@qu.edu.qa

2

Abstract
Surfactant flooding is an important technique used in enhanced oil recovery to reduce the amount
of oil in pore space of matrix rock. Surfactants ar e injected to mobilize residual oil by lowering
the interfacial tension between oil and water and/o r by the wettability alteration from oil5wet to
water5wet. A large number of cationic, anionic, non 5ionic, and amphoteric surfactants have been
investigated on a laboratory scale under different conditions of temperature and salinity.
Selection of the appropriate surfactant is a challe nging task, and surfactants have to be evaluated
by a series of screening techniques. Different type s of surfactants along with their limitations are
reviewed with particular emphasis on the phase beha vior, adsorption, interfacial tension, and
structure5property relationship. Factors affecting the phase behavior, interfacial tension, and
wettability alteration are also discussed. Field ap plications of surfactants for chemical enhanced
oil recovery in carbonate and sandstone reservoirs are also reviewed. Finally, some recent trends
and future challenges in surfactant enhanced oil re covery are outlined. Field studies show that
most of the surfactant flooding has been conducted in low5temperature and low5salinity
sandstone reservoirs. However, high5temperature and high5salinity carbonate reservoirs are still
challenging for implementation of surfactant floodi ng.


Keywords: Surfactant, Interfacial Tension, Adsorption, Chemic al Enhanced Oil Recovery,
Reservoir

3

1 INTRODUCTION
Oil has been the most important and significant sou rce of energy so far, and it will contribute
significantly in meeting the future energy demand a s well
1. Thus, it is necessary to enhance the
current production level in the next few decades, w hich can be achieved by either discovering
new fields or increasing the production from existi ng oil fields. Only about one5third of the oil
present in a reservoir can be recovered using prima ry and secondary recovery techniques
255 . Oil
is initially recovered from a reservoir using the i nherent pressure of the reservoir (primary
recovery). After the dissipation of the initial pre ssure, oil is recovered by applying external
pressure using seawater injection into the reservoi r (secondary recovery). Enhanced oil recovery
(EOR) or tertiary recovery techniques are used to r ecover the remaining oil which cannot be
recovered using water flooding
6. Although chemical EOR (cEOR) is one of the most p romising
methods available to recover residual and remaining oil, it was not very commonly employed in
the past due to low oil prices and the high cost of chemicals. However, continuous rise in oil
prices and the growing demand for oil have encourag ed researchers to determine economical and
low5cost cEOR technology to recover the maximum amo unt of the remaining oil.
In cEOR, a range of chemicals such as surfactants, polymers, and/or alkalis are used to increase
the
Polymers are used to increase the viscosity of the displacing fluid (water), which
improves the oil/water mobility ratio
18521 . On the other hand, microscopic efficiency is rela ted to
the displacement of oil at the pore scale. It is no t possible to displace all the oil that comes into
contact with water during water flooding, due to tr apping of oil by capillary forces. The
relationship between the capillary forces and the v iscous forces results in a dimensionless
capillary number ( 
 

), where µ is the viscosity of the aqueous phase,
v is the velocity
and γ
which is achieved through
the use of surfactants during flooding with brine
26528 . Surfactants also influence the amount of
residual oil recovered via other mechanisms, includ ing micro emulsification of trapped residual
oil, changing the wettability of rock, and improvin g the interfacial rheological properties
29536 .
Here wettability is defined as “the tendency of one fluid to adhere to a solid surface in the
presence of another immiscible fluid”.

4

A large number of surfactants have been evaluated o n a laboratory scale and tested in the field 375
39
. Appropriate surfactants for a set of particular r eservoir conditions are selected after a series of
evaluation steps. Evaluation is based on the surfac tant structure, reservoir temperature, reservoir
salinity, pH, permeability of rock, formation type, cost of the surfactant, adsorption of the
surfactant on the matrix rock, and finally, the oil recovery. The results of several experimental
investigations covering different aspects of surfac tant flooding have been published
40543 . There
are several reviews that cover various aspects of s urfactant and surfactant5polymer flooding.
Seright et al. summarized the polymer requirement i n previous and current polymer floods owing
to their different viscosities and bank sizes
44, 45 . Saboorian et al. established a complete data set
of laboratory experiments, pilot tests, and field a pplications of polymer flood for heavy oil
reservoirs
21, 46 . Olajire 17 reviewed alkaline5surfactant5polymer (ASP) floodin g in general,
discussing the mechanism, prospects, and challenges of ASP flooding. Hirasaki et al. reviewed
mainly role of alcohol, alkali, and chain branching on phase behavior
4. Sheng reviewed the
current status of surfactant EOR technology and sum marized experimental and simulation work
in carbonate and shale reservoirs
47. Raffa et al. reviewed the polymeric surfactants t hat have
been utilized in EOR
48. They collected the relevant work done in last dec ade with a particular
emphasis on patent literature and bio5based systems
48. This review covers different aspects of
surfactant flooding that are not covered in previou s studies. Surfactant flooding is a complex
process and there is a lack of understanding that h ow particular surfactant will behave in typical
reservoir conditions. Due to different types of int eractions of surfactant with brine and other
oilfield chemicals, conflicting results have been r eported in the literature on different aspects of
surfactant flooding such as IFT. In this review, t he phase behavior, IFT, and adsorption of
surfactants is discussed in relation to surfactant structure. The review highlights chemical nature
of various surfactants that was ignored in previous reviews. Field implementation of various
surfactants in carbonate and sandstone reservoirs i s also part of this review. In addition, recent
trends, current challenges, and future directions o f surfactant EOR are also addressed.
The review is divided into different sections to ex plain different aspects of surfactant flooding.
The first section discusses the fundamentals of sur factant EOR that can introduce the readers
with different types of surfactants, oil reservoirs , and screening criteria of surfactants. The
second section discusses the potential surfactant s ystems for EOR that include but not limited to
anionic surfactants, cationic surfactants, zwitteri onic surfactants, viscoelastic surfactants, and
fluorinated surfactants. Subsequent sections discus s the various factors affecting phase behavior,
IFT, adsorption and wettability alteration during s urfactant flooding. Finally, field applications
and challenges of surfactant EOR are addressed.
2 FUNDAMENTALS OF SURFACTANT EOR
2.1 Surfactants
A surfactant is a long5chain molecule which has a h ydrophilic (water soluble) head group and a
hydrophobic (oil soluble) tail group
49. The hydrophobic group may be a long chain hydroca rbon,

5

fluorocarbon, a siloxane chain, or a short polymer chain. The hydrophilic group may be anionic,
cationic, amphoteric, or non5ionic. Surfactant clas sification is mainly based on the nature of the
hydrophilic head group. In anionic and cationic sur factants the hydrophilic group is negatively
and positively charged, respectively. Non5ionic sur factants do not ionize in aqueous solution as
the hydrophilic group is of non5dissociative nature . Water solubility of non5ionic surfactants is
due to the hydrogen bonding between the hydrophilic group, typically an ethylene oxide chain or
a similar group, and water
50. Hydrophilic group is both negatively and positive ly charged in
amphoteric surfactants. Some common hydrophilic gro ups are summarized in Table 1.
The properties of surfactants change considerably a bove and below the critical micelle
concentration (CMC). At the CMC, the surface active ions or molecules in solution associate to
form larger aggregates known as micelles. At a give n temperature and electrolyte concentration,
each surfactant has a unique CMC value. For all sur factants, CMC depends on the chain length
of the hydrophobic tail, temperature, and salinity. CMC decreases by a factor of 2 for ionic
surfactants and a factor of 3 for non5ionic surfact ants for each addition of a methylene group
51.
As the surfactant must be present at a concentratio n higher than the CMC to obtain a lower IFT
and better foam stability, CMC is an important crit erion to be considered in EOR applications.
Also, the maximum adsorption of a surfactant on the reservoir rock surface occurs at the CMC,
above which adsorption do not increase significantl y. CMC is typically determined by plotting a
physicochemical property against the surfactant con centration. CMC can be determined by
surface tension and conductivity measurement, volta mmetry, IR spectroscopy, and nuclear
magnetic resonance spectroscopy.
Another important criterion for the characterizatio n of a single5component surfactant or a
mixture of surfactants is the hydrophilic5lipophili c balance (HLB). It is a measure of the degree
to which a particular surfactant is hydrophilic or lipophilic. HLB can be adjusted either by
varying external parameters, such as the electrolyt e concentration and the solution temperature or
manipulating the structure of the surfactant, such as varying the hydrophobic chain length and
employing a more or less hydrophilic head group
52. A low HLB value (<9) is an indication of a
lipophilic surfactant, while high HLB values (>11) indicate that the surfactant is hydrophilic
53.
Another important surfactant property is the Krafft point, which is the minimum temperature at
which surfactant form micelles. If temperature is < Krafft point, there is no value for critical
micelle concentration; and micelles cannot form
53, 54 . The solubility of a material undergoes a
sharp increase at Krafft point
55.

2.2 Types of Oil Reservoirs
Depending on the formation rocks, oil reservoirs ar e classified either as carbonate reservoirs or
sandstone reservoirs. Sandstone reservoir rock cons ists of a large amount of silica with silicate
minerals, and carbonates are only a minor fraction. Some clay minerals, such as kaolinite and
illite, are also present in sandstone formations
56. Sandstone reservoirs, which are homogeneous,
are the most appropriate for cEOR
57. Carbonate reservoirs, which are estimated to cont ain 60%

6

of the remaining oil, are composed of calcite (CaCO 3), dolomite (CaMg(CO 3)2), anhydrite
(CaSO
4), gypsum (CaSO 4.H 2O), and magnesite (MgCO 3) rocks. Carbonate reservoirs have been
estimated to contain about 3000 billion barrels of the remaining oil and 3000 trillion SCF gas
58.
Some carbonate reservoirs are characterized by frac tures with a high conductivity, which are
surrounded by a low permeability matrix. Most of th ese reservoirs have oil5wet to mixed5wet
conditions. Although carbonate reservoirs have a gr eat potential for the application of tertiary
recovery techniques, EOR research associated with c arbonate reservoirs is limited due to many
technical challenges. Only a few reports on the app lication of cEOR in carbonate reservoirs are
available, mainly due to the high clay content whic h results in significant adsorption of
surfactants
57. Also, carbonate reservoirs are complex and hetero geneous and cEOR is less
effective with carbonates
59, 60 . Precipitation of calcium carbonate and calcium hy droxide occurs
as a result of the reaction of injected surfactants with divalent ions, particularly Ca
++ and Mg ++.
Oil recovery from fractured reservoirs is even lowe r due to poor imbibition of water. In fractured
carbonate reservoirs, surfactants are normally inje cted to change the wettability from oil5wet to
water5wet. Wettability alteration results in the sp ontaneous imbibition of water into the oil
containing matrix, and driving the oil out
58.
2.3 Screening Methodology and Evaluation Criteria
A candidate surfactant for cEOR should have the fol lowing properties: good thermal stability (at
reservoir temperature), ability to lower the oil/wa ter IFT to 10
53 mN/m, low retention on
reservoir rock (<1 mg/g5rock), salt tolerance (at r eservoir salinity), compatibility with the
polymer used, and the commercial availability at an acceptable cost. The selection of a surfactant
requires the careful laboratory screening to determ ine how it will behave in the type of reservoir,
and withstand the reservoirs conditions such as, th e reservoir temperature, formation water
salinity, and the nature of crude oil. Screening me thodology for the selection of surfactants for
cEOR applications is shown in Figure 1. First, the compatibility of the surfactant with other
chemicals and the formation brine is assessed at re servoir conditions. Compatible surfactants are
then subjected to phase behavior experiments, which can screen a large number of potential
surfactants quickly. Surfactants which form a middl e5phase microemulsion are required to obtain
an ultra5low IFT. As the surfactant residence time in a reservoir can be up to a few weeks, the
candidate surfactants should possess long5term ther mal stability. Next, the ability of the
surfactant to decrease IFT and the extent of adsorp tion of the surfactant on reservoir rock
surfaces are determined. Finally, potential surfact ant formulations are used in core flooding
experiments to determine the extent of oil recovery at reservoir conditions. In the following
sections, the phase behavior, IFT, and the adsorpti on associated with various surfactant systems
that have been used in cEOR research to5date will b e discussed. Factors affecting IFT, phase
behavior, and adsorption will also be highlighted.

7

3 POTENTIAL SURFACTANT SYSTEMS FOR cEOR
A large number of surfactants have been evaluated f or cEOR applications. This section will
highlight some important classes of surfactants tha t have been used at the laboratory scale or in
the field. Phase behavior, adsorption, and IFT of d ifferent surfactant classes will be discussed in
the following sections.
3.1 Anionic surfactants
Anionic surfactants are the most widely used type o f surfactant for cEOR applications because
most of the cEOR work has been conducted in sandsto ne formations. Sulfonates, sulphates, and
carboxylates are three important classes of anionic surfactants for cEOR applications.
3.1.1 Sulfonate Surfactants
Most commonly used surfactants for cEOR are sulfona te surfactants. Petroleum sulfonates,
synthetic sulfonates, internal olefin sulfonates, a lpha olefin sulfonates, and alkoxy sulfonates
have been evaluated for cEOR applications
61. The term petroleum sulfonates refers to the
surfactants obtained from the sulfonation of the in termediate molecular weight refinery stream.
Synthetic sulfonates are those surfactants which ar e obtained from the sulfonation of pure
organic compounds
54. Internal olefin sulfonates (IOS), which are a mix ture of surfactants
produced during the sulfonation step, are branched and less viscous. IOS help minimize gel
production and liquid crystal structure formation
61. High Molecular weight IOS have been found
to be more suited for crude oils with a high wax co ntent, high asphaltene content, and a high
viscosity
62. Alpha olefin sulfonates have a linear structure a nd are sensitive to oxygen attack 54.
Sulfonates are stable at high temperature, but as t hey are sensitive to divalent cations, their
performance is limited in high5salinity conditions due to precipitation. Also, the cost of
sulfonates is higher as compared to sulfate surfact ants
63. A mixture of surfactants with a high
equivalent weight and a low equivalent weight is us ed to get a synergetic effect. Sulfonates with
a high equivalent weight are more efficient in redu cing IFT, but are insoluble in water and are
readily adsorbed. Sulfonates with a low equivalent weight act as the adsorbate and solubilizer for
surfactants with a high alkane number
64. Ether sulfonates are stable at high temperature a nd
have a good tolerance to hardness, but they can be expensive and only limited quantities of a few
compounds are commercially available due to manufac turing difficulties. Ether sulfonate
products have short hydrophobes that are not that e ffective for crude oils with high equivalent
alkane carbon numbers (EACN)
65. Alkyl glyceryl ether sulfonates are stable at 110 oC 66.
Examples of other sulfonates include the following: alkyl methylnaphthalene sulfonates;
phenyltetradecane sulfonate; phenyl alkane sulfonat es; sodium dodecyl benzene sulfonate,
hexadecylbenzene sulfonate
and alkyl methylnaphthalene sulfonates; and alkyl glyce ryl
sulfonates, alkyl aryl sulfonates, and alkyl benzen e sulfonates. The typical structure of a
sulfonate surfactant is shown in Figure 2. In summary, most of the sulfonate surfactants are
tolerant to high temperature but not tolerant to hi gh salinity. Therefore, sulfonate surfactants
should be restricted to low salinity environments.

8

3.1.2
Sulphate Surfactants
Surfactants containing the sulfate group have a gre ater tolerance to divalent cations. However,
they do not have the required thermal stability and decompose at temperatures greater than 60
oC
61, 67, 68 . One special class of sulfate surfactants is those based on the Guerbet alkoxy sulfate
(GAS). Guerbet reaction is used to synthesize surfa ctants with a large hydrophobe through
dimerization of a linear alcohol
69. Alkoxy groups like propylene oxide and ethylene o xide can
be used as an extender of the Guerbet alcohol
69. GAS surfactants produced by the alkoxylation
of Guerbet alcohol followed by sulfation can reduce IFT to ultra5low values at high temperature
with different types of crude oil
63. GAS surfactants are chemically stable at high tem perature
provided the pH is maintained in the range of 8511. A high hydrophobicity can be achieved at a
lower cost using GAS surfactants. Sulfate surfactan ts which have been evaluated for cEOR
applications include the following: alcohol propoxy sulfates
70, tristyrylphenol (TSP) alkoxy
sulfate surfactants
71, alkyl ether sulfates, and dodecyl alkyl sulfates 72. In summary, sulfate
surfactants can work well in highly saline environm ents, but they are not chemically stable above
60
oC.
3.1.3 Carboxylate Surfactants
Guerbet alkoxy carboxylate surfactants are stable a t elevated temperatures and can be
synthesized with variable branching options to meet specific reservoir conditions
69. They are
stable at both alkaline and acidic pH and generate ultra5low IFT with low viscosity emulsions for
different crude oils. These surfactants have shown excellent performance with sandstone and
carbonate cores. Alkyl polyoxy propylene/ethylene ( alkoxy) carboxylates (AEC) have good salt
tolerance, high water solubility, good thermal stab ility (up to 120
oC), and high chemical stability
65. Anionic surfactant phosphate esters can also achi eve low IFT at a range of salinities and a
typical structure is shown in Figure 3
73.
In summary, anionic surfactants are the most widely used surfactant for cEOR applications.
However, in general, they do not work well both in highly saline environments and under high
temperatures. The focus of current research is to s ynthesize anionic surfactants that have good
salt tolerance and high thermal stability.
3.2 Non-Ionic Surfactants
As mentioned earlier non5ionic surfactants do not i onize in water and their solubility is
influenced by different factors including hydrogen bonding and van der Waals interactions. An
increase in temperature raises the thermal energy a nd weakens the hydrogen bonding, resulting
in the poor dissolution of the surfactant in water, indicated by a turbid solution. The temperature
at which a non5ionic surfactant solution become tur bid is known as the cloud point
74. The cloud
point depends on the branching of the chain, surfac tant concentration, and the number of
ethylene oxide units. Non5ionic surfactants have a good tolerance to high salinity, but their IFT
reduction ability is lower compared to ionic surfac tants
75. Non5ionic surfactants based on alkyl
polyglycosides can achieve ultra5low IFT using alco hol as the co5solvent
76. Some examples of

9

non5ionic surfactants which have been evaluated for cEOR applications are as follows:
polyoxyethylene stearyl ether (C
18(EO) 20) 77, nonylphenol oxyethylenes 78, alcohol ethoxylates
63, ethylene glycol distearate, and propylene glycol monostearate. The typical structure of a non5
ionic surfactant is shown in Figure 4.
3.3 Zwitterionic Surfactants
Amphoteric surfactants have attracted attention due to their tolerance of high temperature and
high salinity. These properties combined with their very low CMC values, make them suitable to
be used under harsh reservoir conditions
79, 80 . Amphoteric surfactants are expensive as compared
to other surfactants. Amphoteric surfactants that h ave been evaluated for cEOR applications
include the following: carboxyl betaine type surfa ctants, hydroxyl sulfonate betaine type
surfactants, didodecylmethylcarboxyl betaine, alkyl dimethyl propane sultaine, lauramidopropyl
betaine, and cocoamido525hydroxypropyl sulfo betain e. The typical structure of an amphoteric
surfactant is shown in Figure 5.
3.4 Cationic Surfactants
As most of the cEOR projects have been conducted in sandstone reservoirs for which cationic
surfactants are not suitable due to high adsorption , cationic surfactants are the least evaluated for
cEOR applications. As most of the remaining oil is in carbonate formations, cationic surfactants
can be potential candidates for cEOR applications, considering that they have lower adsorption
on calcite and other carbonate minerals
81. Cationic surfactants have been used in combinatio n
with anionic surfactants to have the desirable prop erties. Typically, cationic surfactants used for
cEOR applications are quaternary ammonium salts. Ex amples of cationic surfactants which have
been evaluated for cEOR are as follows: quaternary ammonium salts, gemini surfactant bis

10

spacer group, and examples of spacers are polymethy lene and polyoxyethylene 86. Gemini
surfactants have excellent water solubility, are to lerant to high salinity
87, can significantly lower
the interfacial tension at low CMC, possess interes ting rheological properties, and have
significant potential for cEOR
88590 . Alkyl sulfate Gemini surfactants showed excellent tolerance
to high salinity of 20% NaCl, and ultra5low interfa cial tension was achieved at the higher end of
salinity
87. The synergy between Gemini surfactants and other commercial surfactants can yield
good results in aqueous stability and interfacial t ension reduction
87.
3.5.3 Viscoelastic Surfactants
Viscoelastic surfactants (VES) are a class of surfa ctants that have the desirable property of
mobility control in addition to lowering the interf acial/surface tension. Viscoelastic surfactants
can be ionic or zwitterionic, and unlike classical surfactants which form spherical micelles of oil
in water, VES form a supramolecular structure that causes a surprisingly high viscosity.
Viscoelastic surfactants can be used instead of the combination of a surfactant and a polymer as
it has the desirable properties of both.
Chromatographic effects in the reservoirs can be av oided
by using this single component system. Due to their small molecular size, VES can penetrate low
permeable zones of the reservoir where synthetic po lymers are unable to penetrate.
Only very
limited literature is available on the cEOR applica tion of viscoelastic surfactants in sandstone
reservoirs. There are no published reports on the c EOR application of viscoelastic surfactants in
carbonate reservoirs.
One of the viscoelastic surfactants that have been studied is triphenoxmethanes (TPM)
91 ( Figure
6), which has two hydrophobic groups (R ’ and R ”) and a long chain hydrophilic group (R). The
major advantage of TPM is the stability under harsh conditions of high salinity (18.6% TDS with
a large amount of divalent cations) and high temper ature (greater than 70
oC). Adsorption results
are also acceptable, which indicate that even under these harsh conditions adsorption is not out of
control. However, IFT reduction is not that provide d by other dedicated cEOR surfactants. Some
of the recent investigations on VES as a cEOR fluid have been conducted by our group
92594 .
3.5.4 Polymeric Surfactants
Macromolecules having both hydrophilic and hydropho bic parts in their molecular structure are
usually referred to polymeric surfactants
48, 95 . Technically, amphiphilic polymers, associative
polymers, hydrophobically modified polymers and mic ellar polymers are all polymeric
surfactant. Due to macromolecular nature, they can have a large variety of structures such as
random, block, graft, star and dendrimers. They can be synthesized either by polymerization of
the surface5active monomer or by copolymerization o f hydrophobic and hydrophilic monomers.
Polymeric surfactants can be easily tuned to have d esired aggregation behavior by varying
external factors such as salinity, temperature, and pH. Polymeric surfactants attracted the
attention as they can lower the interfacial tension and improve the rheological properties as well.
Using single component polymeric surfactant in EOR can avoid segregation problems. However,
the interfacial reduction ability of polymeric surf actants is not good compared to conventional

11

surfactants. Another issue associated with the poly meric surfactant is cost associated with raw
material used for polymeric surfactant synthesis.
4 SURFACTANT ADSORPTION
Surfactant retention is one of the most critical pa rameters which can affect the economics of
flooding using surfactants, or surfactant5polymer ( SP) or ASP combinations
96, 97 . Surfactant
retention may be due to precipitation, adsorption, or phase trapping. It is possible to stop
surfactant loss due to precipitation and phase trap ping by selecting temperature and salt tolerant
surfactants and adjusting relevant parameters. Alth ough surfactant loss due to adsorption on
reservoir rock cannot be avoided, it can be minimiz ed. Surfactant retention can decrease the
efficiency of the chemical slug and increase the oi l5water IFT
98. From an economic point5of5
view, surfactant retention should be less than 1 mg /g5rock
99 to be acceptable. Various aspects of
adsorption, which is the main contributor of surfac tant retention in different reservoir rock
surfaces, are discussed in the following sections.
4.1 Mechanism of Surfactant Adsorption on Mineral Surfa ces
The solid5liquid interface develops a surface charge which depends mainly on the pH and ionic
strength
100 . Positively charged surfaces attract anionic surfa ctants while cationic surfactants are
attracted towards negatively charged surfaces
101, 102 . Typically silica and calcite are used as
representative surfaces for sandstone and carbonate formations for cEOR adsorption
experiments. However, they sometime behave differen tly from natural rock due to the presence
of impurities on natural rock
81. Isoelectric point (IEP), which is the pH where a
particular molecule or surface carries no net elect rical charge, for silica and calcite is roughly at
pH 2 and 9, respectively
103, 104 . At pH below the IEP the surface carries a positi ve charge and at
pH above the IEP the surface carries a negative cha rge. Therefore, at neutral pH carbonate rock
is positively charged whereas sandstone is negative ly charged
105 . Silica contains siloxane units
which are bonded together in a tetrahedral lattice
84. For silica, the density of negative charges
remain low below pH 6 and increases sharply above p H 6
106 .
Electrostatic interaction and van der Waals’ interactions between the surfactant hydrophobic
group and the solid surface is believed to be the m ain mechanism of surfactant adsorption on the
rock surface
107 . Surfactant loss can also be due to ion exchange, mineral transformation due to
hydrophobic bonding, ion paring, π electron polariz ation, and the precipitation of surfactant with
dissolved minerals
49, 101, 107 . However, surfactant adsorption is a complex pheno menon and the
driving force of surfactant adsorption at the solid 5liquid interface may be a combination of
electrostatic interactions, chemical interactions, hydrogen bonding, non5polar interactions,
covalent bonding, and de5solvation of the adsorbat e moieties
108 .
Adsorption isotherms are obtained by determining th e surfactant concentration either in the
supernatant liquid in static adsorption experiments or in the effluent liquid from dynamic core
flood experiments. Adsorption obtained from the sta tic adsorption test performed on crushed
rock samples is always higher than the dynamic adso rption due to increased surface area of the

12

rock 68. Surfactant concentration can be determined using the following techniques: conductivity
measurements, two5phase titration, UV spectroscopy, gel permeation chromatography,
potentiometric titration, nuclear magnetic resonanc e (NMR) spectroscopy, gas chromatography,
high performance liquid chromatography (HPLC), and total organic carbon analysis (TOC).
Surfactant structure is most critical in determinin g the adsorption of the surfactant. For example,
in general adsorption of anionic surfactants is hig her on carbonate rocks, while the adsorption of
cationic surfactants is lower because carbonate roc ks are typically positively charged. On the
hand, sandstone rocks are negatively charged, resul ting in a lower adsorption of anionic
surfactants. Adsorption of amphoteric surfactants o n sandstone rock is higher compared to
anionic surfactants due to the electrostatic intera ctions of the positive charge on the head group
of betaine amphoteric surfactant and the negative k aolinite surface
79. Surfactants with longer
chains have a higher tendency to aggregate resultin g in a low CMC value
84.

13

(PO) group can also affect the adsorption of the su rfactant. It was found for various
ALFOTERRA
® surfactants that the increase in the number of pro poxy groups can decrease the
surfactant adsorption on kaolinite
109 . Propoxy groups increase the hydrophobicity of the
surfactant. However, Yu et al. have proposed that t he decrease in the surfactant adsorption is due
to the increase of the interactions among hydrophob ic chains rather than the interaction of the
head group of the surfactant and the kaolinite surf ace
109 .
Ethoxylated alkyl aryl sulfonate surfactant demonst rated lower adsorption on calcite as
compared to its non5ethoxylated counterpart. Equili brium adsorption for the alkyl aryl sulfonate
surfactant is 3.5 mg/m
2 while for the ethoxylated alkyl aryl sulfonate sur factant it is 0.8 mg/m 2
111 . Similar observations were made for the non5ionic ethoxylated surfactants. A significant
decrease in the adsorption of poly(ethylene glycol) mono alkyl ethers on silica was observed
with the increase of the ethylene oxide to hydrocar bon ratio
110 .
An alkali such as sodium carbonate can reduce the a dsorption of anionic surfactants on carbonate
rock
112 . The addition of alkali increases the pH and at pH higher than the IEP the charge on the
carbonate rock reverses. IEP of calcite is 8.559
113 and increasing the pH will reverse the charge
and decrease the adsorption of anionic surfactants. It was found that the adsorption decreases
from 0.22 mg/g to 0.08 mg/g when pH was increased f rom 6 to 11
68. For anionic alkyl aryl
sulfonate surfactants, equilibrium adsorption decre ased from 3.5 mg/m
2 to 0.15 mg/m 2 when 0.3
M Na
2CO 3 solution was added 111 . Propoxylated sulfates, sodium lauryl ether sulfat e, and sodium
nonyl phenol ethoxylated sulfate showed very low ad sorption on calcite in the presence of
Na
2CO 3. Adsorption of sodium lauryl ether sulfate decreas ed by about 90% when Na 2CO 3 is
added
112 , and similar results have been reported by others 114 . Silica, for which IEP is 2, behaves
in a similar manner. At normal formation pH silica carries a negative charge and the adsorption
of anionic surfactants will be low while the adsorp tion of cationic surfactants will be high.
Adsorption of ALFOTERRA
® 63 (an anionic surfactant) on silica was found to increase with
decreasing pH
109 . Alkalis have the additional advantage of consumin g divalent cations present in
the formation and flooding water. However, if anhyd rites are present in the reservoir, the use of
sodium carbonate should be avoided due to the risk of calcium carbonate precipitation
70.
Besides the commonly used alkali Na
2CO 3, some novel alkalis such as sodium tetraborate and
sodium metaborate have also been used. These alkali s form complexes with multivalent cations
instead of precipitation which can cause plugging i n carbonate rocks
79. Sodium metaborate can
tolerate a salinity equivalent to 6000 ppm of Ca
+2 and Mg +2 79, and it has been found to be more
efficient than sodium carbonate
79. Alkali is consumed by reacting with the acid pres ent in the
oil, ion exchange with the clay, and by mixing in t he formation water. Alkali consumption is
normally high in sandstone while in carbonate forma tions there is no significant consumption of
alkali
112 .
Salinity is another important factor affecting the retention of surfactants. Anionic surfactants can
precipitate in high salinity water due to the inter action between different ions and the surfactant
114 . Precipitation is severe in limestone reservoirs d ue to the high concentration of Ca +2 114 . In
other cases, partial solubility of the surfactant d ue to high salinity will increase the adsorption of

14

the surfactant. The increase in salinity can increa se the adsorption of surfactants on mineral
surfaces due to the decrease in the Debye screening length and the decrease in the repulsion
between adsorbed molecules
112 . Adsorption of ALFOTERRA ® 63 increases with increasing
NaCl concentration
109 . Adsorption of anionic, betaine and sulfobetaine s urfactants increases on
limestone and sandstone with the increase of divale nt cations. Increasing the salinity increases
the charged sites on mineral surfaces and the adsor ption of anionic surfactants will increase on
negatively charged surfaces
49. The presence of divalent cations can reduce the a dsorption of
cationic surfactants on carbonates as divalent cati ons make carbonate surface more positive
81,
115
.
The acid number of oil is another important paramet er that determines the retention of
surfactants. Oil with a higher acid number can decr ease the retention of surfactants. The in5situ
generation of surfactant will be higher in oil with a higher acid number. The decrease in the
adsorption from 0.25 to 0.05 mg/mg5rock was observe d when the acid number of the oil was
increased from 0 to 3 mg/ KOH
68.
Adsorption of surfactants may increase or decrease with temperature depending on the
adsorption density
112 . Surfactant adsorption can be either enthalpy5driv en or entropy5driven.
Both the enthalpy and entropy of the system decreas e with increasing temperature. In the case of
enthalpy5driven adsorption (surfactants with low ad sorption density) increasing the temperature
will increase the adsorption density. However, in t he case of entropy5driven adsorption
(surfactants with high adsorption density) increasi ng the temperature will decrease the adsorption
density
112 . Adsorption of ALFOTERRA ® 63 increases with increasing temperature 109 .
Sacrificial agents are also used to decrease the adsorption of surfact ants. Sacrificial agents are
low5cost surfactants that have a higher competitive adsorption. Daoshan et al. used the bio5
surfactant rhamnolipid5fermentation liquor (RH) to decrease the adsorption of alkyl benzene
sulfonate (ORS) on sandstone
116 . The cost of RH is only 15% of that of ORS, and us ing RH
decreases ORS adsorption by 50%, resulting in an o verall reduction in the cost of the ASP
system to 30%
116 . It has been shown that the presence of polyacryla te reduces the adsorption of
anionic surfactants on dolomite above a critical mo lecular weight
117 , indicating competitive
adsorption between the polymer and the surfactant. Flushing sequence is also important in
controlling the extent of adsorption of the surfact ant. When the sacrificial agent and the
surfactant are mixed together adsorption of the sur factant is higher than when the sacrificial
agent is used as a pre5flush
116 .
5 MICROEMULSION & PHASE BEHAVIOR
Phase behavior experiments are helpful in understan ding the performance of different chemicals
and the interactive behavior of brine, surfactants, and crude oil
118, 119 . Phase behavior
experiments can be a very useful tool for screening many surfactant systems. In phase behavior
experiments, phase volume ratios of an oil/water mi xture in the presence of surfactants are
determined. Surfactants form micelles in either the oleic phase or in the aqueous phase
depending upon the hydrophobicity of the surfactant and the salt concentration. These micelles
solubilize some of the excesses of the oleic or the aqueous phase to generate a microemulsion,

15

which is an isotropic, transparent or translucent, and thermodynamically stable dispersion of
water or brine, surfactant, and oil
10. Microemulsions can recover residual oil efficient ly from
sandstone and carbonate reservoirs due to their low interfacial tension
1205122 . Many authors have
reported the principle of microemulsion phase behav ior and its relationship with IFT
1235126 .
Winsor
123 classified microemulsions as Type I (oil in water) , Type II (water in oil), and Type III
(middle phase). In Type I microemulsions, the surfa ctants form micelles in the aqueous phase
and solubilize some of the excess oil in the cores. In Type II microemulsions, the surfactant form
micelles in the oleic phase and solubilize some of the aqueous phase in the cores. In Type III
microemulsions, the oleic and aqueous phases make a bi5continuous network
127 . Microemulsion
phase can be changed from Type I to Type II by tuni ng the salinity at constant temperature and
pressure
128, 129 . An emulsion with a low viscosity and without any gel is required to get low IFT
values
130 . It has been shown that IFT is the lowest when the surfactant has a similar affinity for
oleic and aqueous phases
131, 132 .
In phase behavior experiments the volume of the aqu eous phase, oil phase, and the
microemulsion, determined using a graduated pipette , is used to calculate water and oil
solubilization ratios, which can then be related to IFT
133 . Optimum salinity, oil solubilization
ratio, water solubilization ratio, and the optimum solubilization ratio are important terms used in
the phase behavior experiments. Optimum salinity is defined as the salinity where an equal
volume of water and oil is solubilized in a Type II I microemulsion. Oil solubilization ratio is
defined as the ratio of the volume of oil solubiliz ed (V
o) to the volume of the surfactant (V s).
Similarly, water solubilization ratio is defined as the ratio of the volume of water solubilized
(V
w) to the volume of the surfactant. Optimum solubili zation ratio (σ) is the value of the
solubilization ratio at the intersection of the cur ves of oil and water solubilization ratios plotted
against salinity. Salinity corresponding to the int ersection point gives the optimum salinity
62.
IFT is inversely related to σ by Equation 1;
=

1

where C is constant for a typical crude oil system and its value is approximately 0.3 dynes/cm
62.
The optimum solubilization ratio should be higher t han 10 to achieve a low IFT. Phase behavior
experiments are also useful to determine the equili bration time and the quality of a
microemulsion. Longer equilibration times are due t o high microemulsion viscosity, the
formation of a gel, and liquid crystal structure
71. These viscous structures can reduce the oil
recovery due to high surfactant retention.

16

ratio and nature of alkali. This section will highl ight the details of these factors on phase
behavior. Surfactant structure is one of the most important p roperties which determine phase behavior. For
example, two samples of an internal olefin sulfonat e, which were sulfonated at different
temperatures and with different SO
3/alkene ratios, were compared. The surfactant which was
sulfonated at a high temperature and possessing a h igh SO
3/alkene ratio has a higher optimum
salinity as compared to the surfactant which was su lfonated at low temperature and possessing a
lower SO
3/alkene ratio 61. IOS with greater branching have a higher optimum salinity compared
to IOS with lesser branching, most likely due to hi gher branching increasing the solubility and
thus, increasing the optimum salinity. Branching an d bulky groups in the hydrophobic part
reduce the equilibration time due to the generation of microemulsions of low viscosity and the
prevention of developing viscous and liquid crystal structures
71. Increasing the carbon chain
number of IOS makes it difficult to solubilize the surfactant in saline water
61. When the carbon
chain number of IOS was increased from C
155C 18 to C 205C 24 the optimum salinity decreased from
13% to 4% due to the increase of the hydrophobicity of the surfactant. Meanwhile, the
solubilization parameter increased from 7 to around 19
61.
alkyl alcohol propoxylated sulfate surfactants solubilized all
the oil. On the other hand all the water was solubi lized when surfactant solutions were prepared
in 2 wt % NaCl
109 . Middle phase microemulsions are normally not obse rved without salts 129 .
Varying results have been reported in the literatur e on the effect of temperature on the phase
behavior, optimum salinity and the solubilization r atio. For example, for docusate sodium and
single tail anionic surfactant sodium dodecyl benze ne sulfonate it has been reported that the
increase in temperature increases the optimum salin ity from 1.5 to 5.5 % when the temperature
was increased from 20
oC to 90 oC 134 . On the other hand, increasing the temperature fro m 84 to

17

96 oC for IOS has no effect on the optimum salinity, bu t a decrease in the solubilization
parameter was observed. However, increase in temper ature to 150
oC causes a decrease in the
optimum salinity, which is one of the few cases whe re results obtained at high temperatures have
been reported, most likely due to the effect on the optimum salinity. In most other cases results
reported have been obtained at temperatures not muc h higher than the ambient
61.
Alkali type can also affect the phase behavior and increasing the alkali concentration increases
the optimum salinity to a critical concentration. A bove the critical concentration, optimum
salinity decreases with increasing alkali concentra tion. Under the same conditions, sodium
metasilicate has the highest optimum salinity at ro om temperature, followed by sodium
metaborate and sodium carbonate. The effect of temp erature on the optimum salinity is higher in
the presence of Na
2CO 3 as compared to sodium metasilicate 134 .
Co5solvents are added to prevent the formation of a viscous gel and liquid crystal structures. The
nature of the co5solvent can affect the optimum sal inity differently; a hydrophilic co5solvent,
when used with an anionic surfactant, increases the optimum salinity, while a lipophilic co5
solvent reduces the optimum salinity
135 . Similarly, a short chain co5solvent, such as prop anol,
increases the optimum salinity, while a long chain co5solvent decreases the optimum salinity
136 .
Co5solvents can decrease the equilibration time and the solubilization ratio, which has been
verified for most of the surfactants systems
62. The decrease in the solubilization ratio at the
optimum concentration indicates an increase in IFT. As the addition of co5solvent increases the
cost of ASP or SP flooding, only the minimum amount required to obtain a clear solution should
be used
62. Several strategies have been proposed as an alter native to the use of a co5solvent
including the following: use of a surfactant with b ranching in the hydrophobic chain, adding an
ethoxylated/propoxylated group, and using a mixture of surfactants with different chain lengths
to match the components of the crude oil
137, 138 .

18

6 INTERFACIAL TENSION
Surfactants can reduce the IFT in several ways, inc luding adsorbing at the oil/water interface or
forming mixed micelles
139 . The general rule of thumb is that IFT should be r educed to 0.001
mN/m in order to overcome the capillary forces hold ing the oil in a reservoir
109 . Reduction of
IFT to such a low value means an increase in the ca pillary number by about three orders of
magnitude. Although SP or ASP formulations with ult ra5low IFT are expected to give the
maximum oil recovery, ultra5low values do not neces sarily guarantee the highest oil recovery
48,
140
. Other factors can affect the recovery, and there are reports of cases where the maximum oil
recovery is not from the composition with the lowes t IFT
141, 142 , particularly in heterogeneous
reservoirs. Even though ultra5low IFT can improve t he displacement efficiency, it has a lower
effect on the sweep efficiency. On the other hand, a low IFT value can improve the sweep
efficiency due to the larger grain size of the emul sion
142 . Also, if the surfactant changes the
wettability to water5wet conditions, high IFT will give higher recoveries. Under water5wet
conditions, if IFT is low the recovery process will be gravity driven, while if it is high (>1
mN/m) the process will be capillary driven
143
6.1 Factors Affecting Interfacial Tension
Most of the surfactants showed dynamic IFT behavior between crude oil and water. IFT
decreases with time to a transient minimum value an d increases after achieving transient
minimum value
40, 144, 145 . Dynamic IFT can be used as a test to determine wh ether the crude oil
is free from surface5active species or not. A chang e of IFT between crude oil and brine with time
indicates that there are surface5active species in the oil, which diffuse slowly and result in a
decrease in IFT with time. These surface active spe cies may include emulsion breakers, scale
inhibitors, or rust inhibitors
112 .
6.1.1 Addition of Polymer
Varying results have been reported on the effect of polymers on the minimum IFT value.

19

6.1.2
Surfactant Concentration
IFT displays three types of behavior in different c oncentration ranges. At low concentrations of
the surfactant, IFT normally decreases with the inc reasing surfactant concentration up to an
optimum value. At intermediate concentrations, a fu rther increase in the surfactant concentration
above the optimum value increases the IFT
116, 150, 151 and at high concentrations, IFT decreases
again. The dependence of IFT on the surfactant con centration is due to the adsorption/desorption
of the surfactant at the oil/water interface and th e formation of a stable emulsion. The surfactant
concentration at which the rate of adsorption and d esorption is equal will result in the minimum
IFT. IFT decreases with increasing surfactant conce ntration up to this optimum surfactant
concentration. Further increase in the surfactant c oncentration above the optimum value
increases the IFT due to the high desorption rate o f the surfactant from the interface. Continued
increase in the surfactant concentration results in the formation of a stable emulsion and IFT
starts decreasing again
152 . The increase in the IFT at intermediate concentra tions of the
surfactant is also due to the formation of micelles . At low concentrations, the surfactant is in the
monomer form and a further increase of the concentr ation reduces the IFT due to a large number
of monomer units. The maximum number of monomer uni ts in solution will be at the critical
micelle concentration (CMC). As the concentration o f the monomer decreases due to the
formation of micelles, IFT increases above CMC
152, 153 .

As the interfacial energy is higher for the CH 2 group compared to the CH 3 group, the presence of
more CH
3 groups in the outermost layer will result in a low interfacial tension 154, 155 . Surfactants
with larger hydrophobes are more efficient in lower ing IFT as compared to the surfactants with
shorter hydrophobes
156 . Although the number of PO groups has no effect on the IFT for the
ALFOTERRA
® 3n series at various salinities 109, 111 , IFT decreases with increasing number of
PO groups for the ALFOTERRA
® 2n series 109 and ALFOTERRA ® 6n series 111 . Even though
more hydrophilic surfactants have higher aqueous st ability even under high salinity conditions,
the high hydrophilicity reduces their ability to lo wer the IFT. Increasing the hydrocarbon chain
length makes surfactants more lipophilic
87 and favors their movement from the bulk aqueous
phase to the oil5water interface. Thus, increasing the hydrophobic tail length lowers the IFT.
6.1.4 Presence of Alkali
Alkalis react with the acidic components of crude o il at the oil/water interface and generate an
in5situ surfactant according to following reaction
139 :

where HA is an organic acid and A
5 is the ionized acid. The ratio of ionized to un5io nized acid is
the main factor that determines the IFT and the con centration of the ionized species depends on
their adsorption and desorption rate at the interfa ce. If the rate of adsorption is high the ionized
species accumulate at the interface resulting in th e decrease in IFT. However, if the rate of

20

desorption of the active species is high due to the large concentration gradient, then IFT
increases. Alkalis affect both the minimum IFT and the time required to achieve the minimum
IFT. As it will take some time for the acid at the interface to diffuse and react with the alkali, the
minimum IFT is normally achieved after a time lapse and it is a dynamic process. The
concentration of ionized acid at the interface incr eases with time causing the reduction of the
IFT. The minimum IFT will be at the time when the r atio of ionized acid to un5ionized acid is
equal to 1
139, 157 . As increasing concentration of the alkali increa ses the rate of diffusion and
reaction, the time required to reach the minimum IF T decreases with increasing alkali
concentration
139 . However, an opposite trend has been reported by N asr5El5Din 158 . Although
increasing concentration of the alkali can reduce t he IFT, after a critical concentration IFT may
increase
98, 111, 139, 1585160 . This behavior has been observed for alkyl aryl su lfonate, sodium lauryl
ether sulphate, and propoxylated sulphate surfactan t, which is related to the concentration of the
ionized acid and pH at the interface. The initial d ecrease in the IFT is due to the increase in the
pH and the concentration of ionized species at the interface. After a critical value, the
concentration of the ionized acid decreases due to shifting of the equilibrium or due to the
salting5out effect
139 . Mingzhe et al. proposed another mechanism for the increase of the IFT at
higher alkaline concentration
161 . They proposed that the decrease in the ionic spec ies at high
alkali concentration is due to the formation of mic elles and the compression of the electric
double layer at high ionic strength.
6.1.5 Co-surfactant
In certain cases, the addition of a co5surfactant h elps achieve low IFT values, which depends on
the synergism between the two surfactants. An exten sive amount of literature on the impact of
adding a co5surfactant on the IFT is available
116, 151, 162, 163 . For example, the combination of
alkyl alcohol amide (co5surfactant) and naturally m ixed carboxylate (surfactant) gives a much
lower IFT compared to naturally mixed carboxylate a lone
139 . A similar synergism has been
reported for a bio5surfactant and alkyl benzene sul fonate
116 and other systems 151 . The synergic
effect depends on the interactions between the surf actants and their interactions with the aqueous
and oleic phases. If the surfactant is lipophilic t hen the hydrophilic surfactant may be required to
balance the hydrophilic5lipophilic interactions
151 . The ratio of the surfactant to co5surfactant is
also important. When the interactions between the s urfactants are not strong, equimolar
concentrations will give the minimum IFT
164 . In another study, it was reported that the
combination of a non5ionic surfactant (Tx5100) and an anionic surfactant (sodium dodecyl
benzene sulfonate) has lower IFT as compared to the IFT of the anionic surfactant
146 . This
reduction in the IFT is attributed to the aromatic groups present in the surfactant interacting with
the aromatic hydrocarbons of crude oil to lower the interfacial tension.
An optimum amount of alcohol can be used to obtain an ultra5low IFT. At low alcohol
concentrations, the IFT decreases with increasing a lcohol concentration, but IFT increases after
reaching a minimum with further increase
165 . This behavior is attributed to the competitive
adsorption of the alcohol and the surfactant at the oil/water interface.

21

6.1.6
Salinity
Under high salinity conditions, extremely hydrophil ic surfactants are required for aqueous
stability
63. Surfactants with long carbon chains phase separat e under high salinity conditions 63.
Therefore, short chain surfactants are preferred in high salinity conditions, but they have poor oil
solubilization
63. Salts can significantly change the interfacial pr operties and can result in a
change in IFT for various types of surfactants. At low salt concentration, most of the surfactants
dissolve in the aqueous phase, while at high salt c oncentration surfactants stay in the oleic phase.
However, at the optimum salinity, the surfactant di ssolves equally in the oil and aqueous phases
resulting in the minimum IFT
164 . For the Shengli crude oil/naturally mixed carboxy late system,
IFT decreases as the divalent ion concentration is increased to 300 mg/dm
3, but further increase
of the divalent ion concentration increases the IFT
139 . Similarly, for various ALFOTERRA ®
surfactants, IFT decreases dramatically to a minimu m value when the NaCl concentration is
increased and a further increase in NaCl concentrat ion increases the IFT
109 . Similar behavior has
been reported for other surfactant systems
166 . Liu observed that IFT increases in the presence o f
divalent cations, but the tests were conducted only at a fixed divalent concentration
167 . The
decrease in the IFT with the addition of salt can b e attributed to the decreased hydrophilicity of
the surfactant and its movement to the oil/water in terface
87. However, adding more salt will
result in moving the surfactant from the oil/water interface to the oleic phase resulting in an
increase in IFT.
6.1.7 Temperature
Temperature affects the solubility of surfactants i n water and brine solution and changes the
interaction energy of the head and tail groups. The increase of the temperature can increase the
solubility of the hydrophobic tail in the water and move the surfactant to the oil/water interface
resulting in a decrease in the IFT
87. IFT typically increases with temperature for most of the
reported surfactant systems
144 . For ALFOTERRA ® 35 series, a decrease of IFT between n5
decane and distilled water (DW) with temperature ha s been reported
109 . For various ether
sulfonate surfactants decrease in the IFT with temp erature was observed up to a certain
temperature, and a further increase in the temperat ure resulted in an increase of the IFT
40. The
decrease of the IFT with increasing temperature is due to the decrease in the viscosity of the oil,
which enhances the surfactant migration to the inte rface
40. Effect of temperature on the IFT also
depends on the type of the crude oil. Varying IFT5t emperature behavior was reported for
standard, paraffinic, aromatic, and naphthenic oils . For aromatic oil, IFT was constant up to 50
oC and increases after 50 oC, while for naphthenic oil a decrease in IFT with temperature was
observed. Paraffinic oil showed exactly the opposit e IFT5temperature behavior to that of
aromatic oil
40.
6.2 Measuring Techniques
IFT is measured using the spinning drop technique, which is useful when the surfactant is
available in small quantities. This method is a non 5equilibrium measurement method and results
obtained may be influenced by the time taken for th e temperature to stabilize and the variability

22

of the oil drop in different experiments 130 . Other methods include the pendant drop method 51
and the duNouy ring method
168 .
7 WETTABILITY ALTERATION
Oil reservoirs can be water5wet, mixed5wet, or oil5 wet. Most of the carbonate reservoirs are
fractured, oil5wet, and mixed5wet in nature
1695171 . Wettability concept can be understood by
measuring the contact angle (θ) between the rock su rface and an oil droplet placed on it (contact
angle is the angle of macroscopic meniscus when ext rapolated to zero thickness
172 ). If θ > 90 o
the rock is more oil5wet and if θ < 90
o the rock is more water5wet. In the case of oil5wet rock, oil
is retained by the matrix rock due to capillarity a nd the oil flow is reduced due to trapping of
water globules as the non5wetting phase
170 . In the case of water5wet and mixed5wet carbonate
reservoirs, injected water imbibe into matrix block and displace the crude oil (Imbibition is
defined as the process in which water is displacing oil
173 ). Fractures act as the transport zone for
both water and displaced oil. However, in case of o il5wet reservoirs, spontaneous imbibition of
water cannot take place and the injected water will move towards the production well through
the fractures
168 (Spontaneous imbibition is defined as the imbibiti on that takes place by the
action of capillary pressure and/or buoyancy when m atrix block is surrounded by formation brine
173 ). Therefore wettability is altered from oil5wet to water5wet to recover additional oil.
Use of surfactants to change wettability is one of the techniques adopted by many researchers to
recover oil from oil5wet fractured carbonate and sa ndstone reservoirs
174 . Cationic, non5ionic,
and ionic surfactants have been reported to alter t he wettability of initially oil5wet rock.
7.1 Wettability Alteration by Cationic Surfactants
Organic components of crude oil containing negative ly charged groups are normally adsorbed on
the positively charged mineral surfaces of carbonat es
175 . Interactions occur between the cationic
surfactant monomer and the anionic material (mostly carboxylate) adsorbed on the rock surfaces
from crude oil. Due to ion pair formation between t he cationic monomer and anionic groups,
adsorbed material at oil, water, and rock interface will be desorbed from the rock. The ion pair is
not soluble in the aqueous phase but soluble in the oleic phase. Thus, water will penetrate and oil
will be expelled from the core material. When the a dsorbed material is desorbed from the
surface, it becomes more water5wet and oil can be e xpelled
168 . Mechanism of wettability
alteration by cationic surfactants is shown in Figu re 8. Austad et al. showed that cationic
surfactants can recover additional oil by spontaneo us counter5current imbibition from chalk core
168, 176
7.2 Wettability Alteration by Anionic Surfactants
Anionic surfactants are not able to desorb negative ly charged groups of carboxylate from the
rock surface. Anionic surfactants generate weak cap illary forces through hydrophobic interaction
between the tail of the surfactant and the negative ly charged adsorbed groups
168 . Minor oil

23

displacement by ethoxylated sulfonates from carbona te cores is associated with the formation of
a water5wet bilayer between the carbonate surface a nd oil. Mechanism of the formation of the
bilayer is shown in Figure 9. Alkyl propoxylated su lfates and alkyl aryl sulfonate change the
wettability of calcite from water5wet to oil5wet
177, 178 .

Wettability can be measured by calculating the Amot t–Harvey index of a core before and after
spontaneous imbibition
168, 179 , and the contact angle measurement of a water drop let placed on
the planar surface before and after exposing to the surfactant solution. Wettability alteration
depends on the aging time, surfactant type and conc entration, temperature, crude oil
composition, brine composition, nature of the rock, and water saturation
173, 180 . The increase of
the temperature changes the solubility of adsorbed components, leading to desorption from the
matrix rock making it more water5wet
1815183 . A decrease in the contact angle with temperature
was observed, which confirms the formation of a mor e water5wet state
183 .

8 FIELD APPLICATIONS AND FUTURE CHALLENGES OF SURFACT ANT
EOR
8.1 Comparison of Field and Lab data
Some important surfactants that have been reported for EOR applications in different oil fields
are listed in Table 2. Data indicates that surfacta nt flooding has been utilized in a number of oil
fields around the world. Most of these oil reservoi rs are sandstone reservoirs, and sulfonate
surfactants are the most widely used surfactant. Fi eld applications on chemical EOR show
incremental oil recovery of ~ 12530% of the original oil in place
184 . However, most of the
laboratory reports are showing 20530% incremental o il recovery
20 .
8.2 Economic Overview of Surfactant-Polymer Flooding
No recent update on the cost of chemical EOR are av ailable in the literature especially at current
oil prices that are in the range of $50/bbl. Howeve r, the cost of polymers and surfactants is
dropping and their consumption is low. An increment al barrel of oil is produced by ~ 152 lbs of
polymer, which costs about $1.5/lb. With current oi l prices in the range of $50/bbl chemical
EOR is still economical
184 .
8.3 Challenges and Future Alternate
Challenges for surfactant flooding are in the high5 temperature, high5salinity, fractured carbonate
reservoirs. From the foregoing discussion, it is ev ident that for mild conditions (low temperature,
low salinity) most of the surfactant formulations p erform very well. In the case of high5
temperature and low5salinity conditions, sulfonate surfactants can do the job. However, in high5
temperature and high5salinity sandstone and carbona te reservoirs, many problems arise including
the surfactant precipitation, high adsorption of su rfactants, and chemical degradation. Many

24

attempts have been made to develop surfactants that can tolerate a high5temperature, high5
salinity environment. A recent trend in surfactant EOR is the use of a chelating agent or a
sequestration agent together with the surfactant in high salinity environments to sequester
divalent cations
185 . Some commonly used chelating agents are ethylened iaminetetraacetic acid
(EDTA), tetrasodium EDTA, and sodium acetate
186, 187 . Recently acrylic acid has been used in a
high salinity environment to avoid precipitation
57. The acrylic acid reacts with sodium ions and
forms the precipitation inhibitor sodium acrylate, which reacts with mineral divalent ions and
prevents the formation of precipitates
188 . Alkalis are used to lower the adsorption on miner al
surfaces in soft brines. In the case of hard brines , conventional alkalis precipitate and there is a
risk of maintaining the reservoir integrity. Novel alkalis such as sodium metaborate are
recommended for hard brines
189, 190 . However, a complimentary evaluation has shown tha t high
pH generated by the addition of alkali will eventua lly lead to the reaction of calcium ions with
dissolved carbonate ions and result in precipitatio n
191 . The alternative solution to prevent
precipitation is the use of a chelating agent that makes the economics of the process questionable
192 . Proprietary adsorption inhibitors have also been proposed as an alternative to alkalis 191 .
The combination of other chemicals like polymers an d alkalis is not a new idea. It has been used
in the field and laboratories for decades to achiev e better mobility and oil recovery. Now the
synergetic effect of the surfactant and chemicals o ther than alkalis and polymers has received
attention. In addition, the focus is on the combine d injection of the surfactant and gas to generate
foam as a mobility control agent.
Recently, encouraging results were obtained in usin g nanoparticles in EOR applications.
Nanoparticles such as polysilicon, iron oxide, and silica nanoparticles have been reported to alter
the wettability, to stabilize oil5in5water and wate r5in5oil emulsions, to stabilize CO
2 foam, to
reduce the IFT between oil and water, and finally, to increase oil recovery
1935201 . Based on these
results, attempts were made to investigate combined effects of the surfactant and nanoparticles
2025204 . A surfactant solution with nanoparticles has a lo wer IFT compared to the surfactant
solution without nanoparticles. Adsorption of the s urfactant also decreases in presence of
nanoparticles. Moreover, oil recovery is better as compared to the surfactant alone. Similarly
using non5ferrous metal particles with an anionic s urfactant resulted in higher oil recovery and
lower surface tension
205 . Other nanoparticles which are investigated in nan oparticles5surfactant
systems are alumina, zirconia, and silica
203, 206, 207 . Oil recovery efficiency is higher for slightly
hydrophobic nanoparticles as compared to hydrophili c nanoparticles. Zirconia particles also
increase the viscosity of the surfactant solution a nd change the flow characteristics from
Newtonian to non5Newtonian
203 . Surfactant alternating gas (SAG) injection is now being used in
heterogeneous formations to prevent early breakthro ugh due to overriding and fingering
208 . The
generated foam increases the viscosity of the gas, and better mobility control is obtained using
SAG injection.

25

9 CONCLUDING REMARKS
A range of surfactant systems is reviewed for EOR a pplications. Mainly these surfactants are
sulfonates, sulfates, carboxylates, cationic surfac tants, non5ionic surfactants, and amphoteric
surfactants. Some special classes of surfactants in cluding Gemini surfactants, surfactants based
on Guerbet alcohol, fluorinated surfactants, and vi scoelastic surfactants are also discussed. Phase
behavior, interfacial tension, adsorption, wettabil ity alteration, and field applications are
discussed as well. Reservoir conditions such as the temperature, salinity, type of rock, charges on
rock, pH, and heterogeneity are main parameters tha t should be considered before the selection
of a surfactant. Surfactants for EOR applications a re screened using a series of evaluation criteria
based on the compatibility, phase behavior, thermal stability, interfacial tension measurement,
adsorption, and core flooding. Field studies show t hat most of the surfactant flooding has been
conducted in low5temperature and low5salinity sands tone reservoirs, and sulfonate surfactants
are the most widely used surfactants in these appli cations. However, sulfonate surfactants do not
tolerate high salinity and hard brines, and most of the remaining oil is in high5temperature and
high5salinity carbonate reservoirs. To extend surfa ctant flooding to high5temperature and high5
salinity reservoirs, work on different strategies i s underway. For carbonate reservoirs, amphoteric
surfactants can be a better option due to good ther mal stability and aqueous stability. Polymeric
surfactants are a possible alternative to surfactan t5polymer and alkali5surfactant5polymer
flooding.
10 ACKNOWLEDGMENT
This research is supported by Saudi Aramco through project # CPM 2297. Authors would like to
thank Center for Petroleum & Minerals, King Fahd Un iversity of Petroleum & Minerals
(KFUPM) for supporting this research.

26

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43

List of Figures
Figure 1: Flow chart of the surfactant screening pr ocedure for cEOR applications
Figure 2: Typical example of a sulfonate surfactant (sodium dodecyl benzene sulfonate)
209
Figure 3: Typical structure of a phosphate surfacta nt (phosphate ester)
73
Figure 4: Typical example of a non5ionic surfactant (polyethoxylated octyl phenol)
209
Figure 5: Typical example of an amphoteric surfacta nt (Dodecyl betaine)
209
Figure 6: Structure of TPM: R’ and R” are hydrophob ic groups and R is a long chain hydrophilic
group (R)
2
Figure 7: A typical surfactant adsorption isotherm on Berea sandstone
49
Figure 8: Mechanism of wettability alteration for c ationic surfactants. Circles represent the
cationic surfactant molecules and squares represent the anionic surface active material present in
the oil
210
Figure 9: Mechanism of the formation of the bilayer with ethoxylated sulfonate. Ellipses
represent the anionic surfactant and squares repres ent the carboxylate material present in the oil
210
List of Tables
Table 1: Some common hydrophilic groups of surfacta nts
Table 2: Reported fields where surfactants have bee n used in EOR either as a surfactant flood or
SP flood

44


Figure 1: Flow chart of the surfactant screening procedure for cEOR applications

Select Surfactant
Is it
compatible
Compatibility &
phase behavior
Thermal Stability at reservoir conditions
Is it
stable?
IFT
Surfactant is not
suitable
Surfactant is not suitable
Adsorption
Core flooding
Decision
No
Yes
No
Yes

45



Figure 2: Typical example of a sulfonate surfactant (sodium dodecyl benzene sulfonate)
209

Figure 3: Typical structure of a phosphate surfacta nt (phosphate ester)
73

Figure 4: Typical example of a non5ionic surfactant (polyethoxylated octyl phenol)
209

Figure 5: Typical example of an amphoteric surfacta nt (Dodecyl betaine) 209

46


Figure 6: Structure of TPM: R’ and R” are hydrophob ic groups and R is a long chain hydrophilic
group (R)
2


Figure 7: A typical surfactant adsorption isotherm on Berea sandstone 49

47


Figure 8: Mechanism of wettability alteration for c ationic surfactants. Circles represent the
cationic surfactant molecules and squares represent the anionic surface active material present in
the oil
210

Figure 9: Mechanism of the formation of the bilayer with ethoxylated sulfonate. Ellipses
represent the anionic surfactant and squares repres ent the carboxylate material present in the oil
210

48

Table 1: Some common hydrophilic groups of surfacta nts
Type of SurfactantS Hydrophilic Group
Non-ionic Polyoxyethylene, polyols,
Sucrose esters, polyglycidyl
esters

49

Table 2: Reported fields where surfactants have bee n used in EOR either as a surfactant flood or
SP flood

Country Field Formation type Surfactant Ref.

Bradford field sulfonate
Cretaceous upper
Edwards carbonate petrostep5B100
The cottonwood creek carbonate polyoxyethylene alco
hol ,
218
Bob slaughter block mixture of petroleum sulfonate
and alkylaryl ether sulphate
Yates fields carbonate non5ionic ethoxy alcohol
Tanner sandstone ORS541
Sho5vel5tum 5 5
Gudong sandstone
Karamay sandstone petroleum Sulfonate 229 ,
230
Xing long tai sandstone 5

Baturaja carbonates 5
Argentina Chihuido de la sierra negra SS56066
Germany Bramberge sandstone olefin sulfonate
X